Abstract A suite of crude oil samples, that had not been

previously characterized geochemically, was collectedfrom two oil fields in the southwest Niger Delta Nigeria.The saturate biomarkers were used to evaluate geochemicalcharacteristics such as depositional environments, sourcesof organic matter and extent of biodegradation using gaschromatographyflame ionization detector and gas chromatographymass spectrometry. Distribution of n-alkanes(Pr/Ph, and isoprenoide/n-alkanes ratios), the abundance ofhopanes, oleanane skeleton and C27C29 steranes in the oilsindicate that they were formed from mixed sources (marineand terrestrial kerogen) deposited in an oxic paleoenvironment with no particular maturity trend. These parameters also permit the source grouping of the oils into twofamilies.Keywords Biomarkers Paleoenvironment Biodegradation Hopanes Oleanane

1 IntroductionCrude oil study, which utilizes the detailed geochemicalanalysis of a representative suite of samples, is an excellentway of identifying and comparing samples sourced from asource rock located in a relatively close area (Doust andNoble 2008). Crude oil is a complex combination ofhydrocarbons, ranging from C1 to C60?, and it consistspredominantly of aliphatic, alicyclic and aromatic hydrocarbons. It may also contain small amounts of nitrogen,oxygen and sulfur compounds, some organometallic complexes, notably of sulfur and vanadium, and dissolvedgases, such as hydrogen sulfide.The geochemical evaluation of source, depositionalenvironment and maturity levels of crude oils help locatehydrocarbons in the explored areas and different stratigraphic units of the basin (Akinlua et al. 2007). This is alsouseful in petroleum exploration and production because itdevelops tools to describe, understand and predict theformation of oil and gas, their migration, the thermal history of the basins and the composition of the fluids thathave passed through them. It can also serve for the characterization and production of the hydrocarbon fields, theidentification of source rocks and the classification of crudeoils into families (Karlsen et al. 1995; Larter and Aplin1995; Huc 2003).Geochemical methods of crude oil characterizationinclude biomarker fingerprints, use of bulk parameters,stable isotope ratios, hydrocarbon contents, etc. (Barwise1990; Udo et al. 1992; Oluwole et al. 1993). This mainlyrelies on gas chromatographymass spectrometry (GCMS) for the analysis of biomarkers. It is also responsiblefor the rapid development of petroleum geochemistry andits application in the oil and gas industry during exploration(Killops and Killops 1993).

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Biomarkers provide information on the organic source

materials, environmental conditions during deposition,thermal maturity experienced by a rock or oil and thedegree of biodegradation (El-gayer et al. 2002).The hydrocarbons found within the basin in the NigerDelta occur at different productive horizons that are at verygreat depths apart (Sonibare et al. 2008). In the NigerDelta, a variety of studies have been carried out in order todetermine the location and effectiveness of the regionssource rocks (Knox and Omatsola 1978; Ekweozor andDaukoru 1994). But despite these in-depth studies, noconsensus has yet emerged concerning the true identity ofthe petroleum system(s) that have contributed to the greaterNiger Delta oil fields (Eneogwe and Ekundayo 2003).This work is aimed at evaluating the geochemical relationship between the crude oils from two different fields inthe southwest Niger Delta and to ascertain the source oforganic matter, their depositional environment and theirmaturity levels.

Abakaliki high and further east south east by the Calabar

flank, a hinge line bordering the adjacent Precambrian. Theoffshore boundary of the province is defined by the Cameroon volcanic line to the east and the eastern boundary ofthe Dahomey basin (the eastern-most West African transform-fault passive margin) to the west. There are the 2-kmsediment thickness contour or 4,000-m bathymetric contour, in areas where sediment thickness is greater than2 km, to the south and southwest (Michele et al. 1999).

2 Materials and methods

2.3 Fractionation of the oils

2.1 Province geology of Niger Delta

The crude oils were fractionated into saturates, aromatics

hydrocarbons and polar compounds by column chromatography on a silica gel. The standard glass column, whichis 50 cm in length and 0.5 cm in internal diameter, wasrinsed first with dichloromethane (DCM) and later withlight petroleum spirit (petroleum ether). The column wasthen plugged with cotton wool, to serve as a resting pad forthe stationary phase silica gel (SiO2) and filled withpetroleum ether. Then, the stationary phase (SiO2) wasintroduced. Two (2 g) of Alumina was added to keep thesurface stable. An oil sample was introduced, followed bythe eluents, gently. 70 ml of petroleum ether was added toelute the aliphatic fraction and 70 ml of DCM was used toelute the aromatic fractions, while 70 ml of methanol wasused to elute the polar (resins). The aliphatic fractions werereduced with nitrogen stream to near dryness and thendiluted with DCM for GCMS analysis.

The study area lies within the Niger Delta; its geology istherefore typical of the Niger Delta Basin. The area formspart of a geological sequence of the Quaternary and Tertiary formations of the Niger Delta, consisting mainly ofthree main geologic formations: The Benin Formation,Agbada Formation and Akata Formation (Sundararamanet al. 2002). The Niger Delta province is the twelfth largestin the world with about 34.5 billion barrels of recoverableoil and 93.8 trillion cubic feet of recoverable gas. It issituated in the Gulf of Guinea and extends throughout theNiger Delta Province, as defined by Klett et al. (1997).From the Eocene to the present, the delta has progradedsouthwestward, forming depobelts that represent the mostactive portion of the delta at each stage of its development(Doust and Omatsola 1990). These depobelts form one ofthe largest regressive deltas in the world with an area ofsome 300,000 km2 (Kulke 1995), a sediment volume of500,000 km3 (Hospers 1965) and a sediment thickness ofover 10 km in the basin depocenter (Kaplan et al. 1994).The petroleum system of the Niger Delta is referred to asthe Tertiary Niger Delta (AkataAgbada) Petroleum System (Fig. 1).The onshore portion of the Niger Delta Province isdelineated by the geology of southern Nigeria and southwestern Cameroon (Fig. 1). The northern boundary is theBenin flank, an east-northeast trending hinge line south ofthe West Africa basement massif. The northeasternboundary is defined by outcrops of the Cretaceous on the

2.2 Sample collection

A suite of crude oil samples was collected from two different producing fields onshore, in the southwest NigerDelta. The crude oils were collected with glass vials withTeflon caps and, prior to laboratory analysis, stored in therefrigerator at a temperature of less 4 C.2.2.1 Sample preparation for gas chromatographic massspectroscopy analysis (GCMS)

2.4 GCMS analysis

The GCMS analyses for the aliphatic hydrocarbons of theoils was performed using a Hewlett-Packard 5890II GCwith a split/splitless injector (280 C) linked to a HewlettParkard 5972 MSD with an electron voltage of 70 eV,filament current of 220 lA, source temperature of 160 C,a multiplier voltage of 1600 V and interface of temperature300 C. The acquisition was controlled by an HP VectraPC chemstation computer in both full scan mode andselected ion mode. The sample (1 ll) in DCM was injectedby an HP7673 auto-sampler and the split opened after

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1 min. Separation was performed on a fused silica capillary

column (30 m 9 0.25 mm i.d.) coated with 025 lm, 5 %phenylmethylsilicone (HP-5). The GC was temperatureprogrammed for 40300 C at 4 C per minute and held atthe final temperature for 20 min. The carrier gas washelium (flow 1 ml/min., pressure of 50 kPa, slit at 30 ml/min.). The acquired data was on a DAT tape for laterprocessing. The data was processed using Chem StationG1701BA (version B.01.0019891998) software and theintegration of peaks was done with the RTE integrator.Figures 2, 3 and 4 show the GCMS chromatograms of thecrude oils samples.

3 Results and discussion

3.1 Normal alkanes and isoprenold distributionIn the geochemical evaluations of crude oils, the ratios ofisoprenoids to n-paraffin are often used for oil-sourcecorrelation, maturation and biodegradation studies (Ekweozor et al. 1981). Various ratios of isoprenoids to nalkanes were computed such as the Pr/Ph, Pr/nC17, Ph/nC18, nC25/nC18, (Pr ? C17)/(Ph ? C18) (Table 1). Thegas chromatogram of the normal alkanes and the isoprenoids is shown in Fig. 2. The pristane/phytane (Pr/Ph) ratiois one of the most commonly used geochemical parametersand has been used as an indicator of depositional environment, though with low specificity due to the

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interferences of thermal maturity and preliminary assessment of organic matter source inputs (Peters et al. 2005). Itis also widely used as indicator of redox potential of thedepositional environment. Ten Haven (1996) stressed thathigh Pr/Ph ([3.0) indicates terrigenous input under oxicconditions and low Pr/Ph (\0.8) indicates anoxic/hypersaline or carbonate environments. Low values of the Pr/Ph(\2) indicate aquatic depositional environments includingmarine, fresh and brackish water (reducing conditions),whereas high values (up to 10) are related to peat swampdepositional environments (oxidizing conditions) (Roushdyet al. 2010). The studied oil samples are characterized bypristane/phytane ratios, which ranged from 3.36 to 4.05 and1.88 to 2.31, thus confirming that these oils originated fromterrigenous organic matter deposited under an oxic paleoenvironment. Sample U4L is slightly different from othersamples; it has a Pr/Ph ratio of 1.88 (\2), indicating anaquatic environment. Pr/nC17 ratios range from 0.44 to1.35, while Ph/nC18 ratios range from 0.16 to 0.65. Therelatively high Pr/Ph ratios of some of the oils indicate theirhigh maturation levels.Several authors have used a plot of Pr/nC17 versus Ph/nC18 to classify oils and rock extracts into differentgroups (Fig. 5). Source, maturation, migration and biodegradation are the major factors responsible for thedifferences in crude oil composition. Values less than 1.0are indicative of non-biodegraded oils. Both Pr/nC17 andPh/nC18 decrease with maturation, due to the increasingprevalence of the n-paraffin. The values of Pr/Ph, Pr/nC17

Fig. 3 GCMS chromatograms of m/z 191 for crude oil samples

and Ph/nC18 for the analyzed crude oils are given in

Table 1. All samples have Ph/nC18 less than one (\1.0),suggesting that these samples are non-biodegraded (Hunt;1996).

3.2 Carbon preference index (CPI)

The CPI was the first maturity indicator applied to crudeoils (Peters et al. 2005; Muhammad et al. 2010). Some

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U7L

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Fig. 4 GCMS chromatograms of m/z 217 for crude oil samples

researchers observed that immature rocks often had high

CPI values ([1.5). The CPI values ranges between 0.72and 1.09 for all crude oils (Table 1), so approximately 1.0,implying these are slightly or marginally mature oils.Figure 6 is a plot of pristane/phytane versus CPI that showsthe depositional environment of the oils. Moldowan et al.(1985) concluded that an odd carbon preference is characteristic of oils derived from source rocks deposited innon-marine depositional environments. If the total evenand odd numbers of paraffins are equally abundant, thevalue of the (CPI) will be equal to one, as is generallyobserved in high maturity samples (Tissot and Welte1984).In these studied oil samples, a slightly odd-over-evenpredominance of higher molecular weight n-alkanes (nC24nC35) has been observed, producing CPI values ofapproximately 1.0 (Table 1). The observed CPI values inmost of the study samples are believed to be influenced bythe type of organic matter and the thermal maturity, as allsamples are known to possess some level of maturity.Listed in Table 1 are the calculated values of the CPI of thecrude oils samples. Sample U7L value is 0.76, indicatingthat the sample is more mature than other samples. None ofthe samples under study are above 1.5.The plot of Ts/(Ts ? Tm) versus 20S/(20S ? 20R)(Fig. 10) showed some correlation, indicating that Ts/(Ts ? Tm) increases linearly with 20S/(20S ? 20R)

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(Hanson et al. 2000; Seifert and Moldwan 1986; Peters and

Moldowan 1993). The plot also indicates that the KD 01KD 03 oils samples show a fair cluster, implying very closematurity ranking. However, the U2T, U45, U4L and U7Loil samples show a slight variability in the maturity of theoils. These agree with the concept of lateral maturity gradient representing successive charging fronts with varyingmaturity ranks.3.3 Saturated biomarker distributionPeters and Moldowan (1993) showed that the Hopanes andSteranes include the biomarkers commonly used formaturity assessment. Figures 3 and 4 are the m/z 191(hopanes) and 217(steranes) chromatograms for the saturatedbiomarkers distribution of studied crude oil samples. Itshows that the pattern of all samples belongs mostly to the17a (H), 21b (H) hopanes series, with molecules rangingfrom C27 to C35. The C30 regular hopane is the most predominant member series, followed by C29 norhopane. Theratio of C29/C30 is in the range of 0.620.69 (Table 1). Theratio of 18a (H)-trisnorneohopane (Ts) and 17a (H)trisnorhopane (Tm) ranges from 0.79 to 1.47. The 17b (H),21a (H) series of molecules (mortetanes) and the compound are also present in varying abundance. The ratio ofTs to Tm increases by more than 0.5 times as the portion ofshale in the calcareous facies increases (Hunt 1996). This

ratio proved to be useful, though not as decisive as a

maturity parameter (Seifert and Moldwan 1986). VanGraas (1990) stated that the Ts/Tm ratios begin to decreasequite late during maturation, but Waples and Machihara(1991) reported that the Ts/Tm ratio does not appear to beappropriate for the quantitative estimation of maturity.There was no distinct variation in the observed values forthe Tm/Ts ratios among the samples studied. This ratiomay not be indicative of thermal maturity, but rather maybe strongly influenced by the source differences among theoils (Palaces and Anders 1984).Oleanane is present in all the study samples and isidentified as one peak representing 18a (H)-oleanane and18b (H)-oleanane. The extended hopanes, which occur asstereoisomeric pairs from C31 to C35, occur as either 22S or22R epimers. The presence of the oleananes is a goodindicator of a terrestrial input into the oil-prone sourcerocks deposited in a deltaic environment (Ekweozor et al.

1979., Philip and Gilbert 1986). Various studies show that

oleananes may be considered reasonably reliable indicatorsof higher plant source material. Hopane (C30) ab/ab ? baand homohopane (C32) 22S/(22S ? 22R) ratios for the oilsrange from 0.85 to 0.88 and 0.52 to 0.58, respectively(Table 1). These values are consistent with the oils generation from the early mature source rocks (Seifert andMoldwan 1986, Peters and Moldowan 1993).The ratios of C29/C30 hopanes ranges from 0.60 to 0.69.Values greater than one indicate oil generated from organicrich carbonates and evaporates (Connan et al. 1986). Allthe studied oil samples have C29/C30 hopane ratios of lessthan one (Table 1). This data illustrates that the oil samplesare not sourced from source rocks rich in carbonaceousorganic matters (Waples and Machihara 1991).The distribution of 17a, 21b (H)homohopanes22R ? 22S C35/(C31C35), also known as the homohopaneindex in crude oils, can be used as an indicator of the redox

potential to evaluate the oxic/anoxic conditions during and

immediately after the deposition of the source sediments(Peters and Moldowan 1993). The studied crude oils have alow homohopanes index (0.010.05), which suggest anoxic deposition environment of the oil (Sonibare et al.2008).The m/z 217 ions mass chromatogram shows the distribution of steranes for crude oil samples in Fig. 4. Steranes include the biomarkers most commonly used formaturity assessment (Peters and Moldowan 1993). Mackenzie (1984) stated that ratios involving different carbonnumbers, in the range of C27C29 steranes, were used todetect source differences. The predominance of C29 steranes is shown by the organic matter with higher plantinputs, while the marine organic matter shows higher C27steranes. Some of the studied crude oils are characterizedby the predominance of C28 and C29 over C27 steranes(Fig. 7), while the second group of oils show that the

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dominance of C29 over C27 and C28 steranes (Fig. 8).

Figure 7 indicates that the crude oils are derived frommixed terrestrial and marine organic sources; while Fig. 8has more of a higher terrestrial input. These assumptionsare confirmed by the steranes ternary diagram (Fig. 9).The regular steranes/17a (H)-hopanes ratio (sterane/hopane ratio) is relatively high in marine organic matter,with values generally approaching unity or even higher. Incontrast, low steranes and sterane/hopane ratios are moreindicative of terrigenous organic matter (Noriyuki et al.1996). The studied crude oils steranes/hopanes ratio rangefrom 0.02 to 0.20 (Table 1). This indicates that themajority of the studied crude oils are generated from terrigenous organic matter. These results are in agreementwith the data obtained from the relationship between Pr/nC17 and Ph/nC18 (Fig. 5).The steranes (C29) 20S/20S ? 20R abb/abb ? aaavalues range from 0.46 to 0.63 (Table 1). These low valuessupport the low maturity status of the oils (Seifert andMoldwan 1986). The ratios of 22S/22S ? 22R for theextended hopanes were also calculated and were found tohave little variation with each other. The 22S/(22S ? 22R)extended hopanes and 20S/(20S ? 20R) C29 steranes (aaa/aaa ? abb; abb/abb ? aaa), which are used as maturityindicators, are close to the equilibrium value of 0.570.62proposed by Peters and Moldowan (1993). The 22S/22S ? 22R ratio has an equilibrium value of 0.55, whichcorresponds to the onset of hydrocarbon generation(Mackenzie 1984). There is no well-established maturitypattern observed between the indices used as the maturityparameters and the cross plots. The level of thermalmaturity of the crude oils suggests either that the organicmatter generating oils may have been buried at a considerable depth in the sediment or that these samples wereseverely affected by thermal metamorphism (Burgan andAli 2009) (Fig. 10).3.4 Depositional environmentOleananes are specific biomarkers that originate fromhigher plant triterpenoid, not from a bacterial origin. Theyare specific to some angiosperms (flowering plants), afactor that also limits the source-rock age to the Tertiary orUpper Cretaceous and a proximal depositional environment. They occur in many terrestrial oils and shales, oftenin deltaic environment (Ekweozor et al. 1981). Moldowanet al. (1994) suggested that an oleanane index above 0.3 isan indication of crude oils derived from rocks of Tertiaryage. From Table 1, it is apparent that most of the crude oilsoriginated in the terrestrial environment of the Tertiary age.Alberdi and Lopez (2000) used the characterization of18a (H)-oleanane in oils to determine organic type and theage indicator for the assessment of the petroleum system.

Chin. J. Geochem. (2015) 34(2):224232

Fig. 10 Plot of Ts/(Ts ? Tm) vs 20S/(20S ? 20R)

Fig. 8 Bar chart of %C27, %C28 and %C29 steranes showing

dominance of %C29

This work presents a geochemical approach that enables

accurate discrimination between oil samples from twodifferent oil fields within the southwest of the Niger Delta.This study also reveals that the crude oils were derivedfrom source rocks containing mixed kerogen (marine andterrestrial) that were deposited in an oxic environment. Gaschromatographic fingerprinting of the crude oils from thestudied fields has provided an insight into the source signature of the hydrocarbon materials under investigation.Saturated hydrocarbon and molecular composition hydrocarbon composition of the crude, the distribution ofn-alkanes/isoprenoids and the high Pr/Ph ratios suggest thatthe oils were derived from source rock with a significantterrestrial contribution and were deposited in an oxic paleoenvironment. The calculated CPI and steranes, whichwere used in determining the maturity level of the crudeoils, could not ascertain their specific maturity pattern.Acknowledgments The researchers are sincerely grateful to theNigerian Department of Petroleum Resource (DPR) and PlatformPetroleum Nigeria Limited for granting us access to the crude oilsamples used for this research work. We also appreciate the efforts ofMrs. Yvonne Hall of Newcastle University, United Kingdom and Mr.Oteiva Frank of Chromatography Laboratory, INDORAMA-Elemepetrochemical Company Ltd for their assistance during some of thelaboratory analyses of the crude oil samples.

Fig. 9 Ternary plot for relative proportions of the C27C29 steranes

from both Umutu and Bomu

Type 1 oils show a high relative abundance of gammacerane, indicating a marine saline-source depositional environment. Furthermore, these oils have a predominance ofC35 to C34 17a (H)-homohopanes and Type 2 oils have anoleanane content of more than 20 % of the concentration ofC30 ab hopane, indicating that they originated from anangiosperm-rich, tertiary source rock (Moldowan et al.1994).